CN103562752B - The measurement of stratum maximum depth of exploration - Google Patents

Abstract

It relates to a kind of method of volume for determining the cleaning thing around drilling well.Provide a kind of logging tool.Described logging tool can be disposed on cable, drill string or wired drill pipe.Use described logging tool to obtain formation characteristics.Described formation characteristics may include that voltage, body resistivity, horizontal resistivity, vertical resistivity, porosity, permeability, fluid saturation, NMR relaxation time, drilling well size, drilling well shape, drilling fluid compositions, MWD parameter or LWD parameter.Using model response and noise level to determine the maximum depth of exploration entering subsurface formations, determined by use, maximum depth of exploration determines the volume of cleaning thing.Even if not detecting boundary region, it is also possible to determine maximum depth of exploration and the volume of cleaning thing.

Description

Measurement of Maximum Exploration Depth of Formation

technical field

The present disclosure relates generally to logging a subterranean formation around a wellbore using downhole logging tools, and more particularly to determining the maximum depth of investigation for measurements made in the formation.

Background technique

Well logging tools have long been used downhole to make measurements such as formation evaluation to infer properties of the formation around the wellbore and the fluids in the formation. Common logging tools include electromagnetic tools, nuclear tools, and nuclear magnetic resonance (NMR) tools, although various other tool types are also used.

Early logging tools were attached to wirelines into the well after the well was drilled. Modern versions of this wire tool are still widely used. However, the need for information while drilling has given rise to measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools. MWD tools typically provide information on drilling parameters such as weight on bit, torque, temperature, pressure, direction and inclination. LWD tools typically provide formation evaluation measurements such as resistivity, porosity and NMR distribution. MWD and LWD tools often have common wireline tool components (eg, transmit and receive antennas), but MWD and LWD tools must be built to not only withstand the harsh drilling environment, but also operate within it.

Prior art tools and methods have focused on determining and displaying (mapping) the distance between on-tool survey sensors and formation boundaries. Identification of formation boundaries is often characterized by a change in one or more physical properties of the formation. Various techniques and working methods exist to assess distances to boundaries, but none of them allow for the determination of formation volumes from survey depth and azimuth measurements in the absence of identifiable formation boundaries, or in the case of surveys, depth Relatively close stratigraphic boundaries are read in adjacent strata.

Contents of the invention

The present disclosure relates to a method for determining a volume of clearance around a wellbore. A logging tool is provided. The logging tool may be deployed on wireline, drill string or wireline drill pipe. Formation properties can be obtained using this logging tool. The formation properties may include voltage (not strictly a formation property but included here as it can be used where formation properties are used), bulk resistivity, horizontal resistivity, vertical resistivity, porosity , permeability, fluid saturation, NMR relaxation time, magnetic field induced by current, acoustic response, well size, well shape, drilling fluid composition, MWD parameters or LWD parameters. The model response and noise level are used to determine the maximum exploration depth into the subsurface formation, and the determined maximum exploration depth is used to determine the volume of the cleanup. The maximum depth of exploration and volume of clearance can be determined even if no boundaries are detected.

Other aspects and advantages will be readily apparent from the following description and appended claims.

Description of drawings

Figure 1 illustrates an exemplary wellsite system.

Figure 2 shows a prior art electromagnetic logging tool.

3 is a graph of signal strength versus depth of investigation according to the present disclosure.

FIG. 4 is a flowchart illustrating steps according to an exemplary embodiment of the present disclosure.

Figure 5 schematically shows a three-layer model with the logging tool positioned two feet below the upper formation.

6A-6D are graphs of signal difference with and without a lower boundary as a function of the distance between the logging tool of FIG. 5 and the lower boundary.

detailed description

Some embodiments will now be described with reference to the figures. For reasons of consistency, the same reference numerals will be used for the same parts in different drawings. In the following description, numerous details are set forth to provide an understanding of different embodiments and features. However, it will be understood by those skilled in the art that some embodiments may be practiced without many of the details and that many variations or modifications are possible from the described embodiments. As used herein, the terms "above" and "below", "upper" and "downward", "upper" and "lower", "ascending" and "descending", and other similar descriptions relative to a given point or element Terms of position above or below are used in the specification to more clearly describe a particular embodiment. However, when using devices and methods in deviated or horizontal wells, these terms may refer to left-to-right, right-to-left, or diagonal relationships, as appropriate.

Figure 1 illustrates a wellsite system in which various embodiments may be used. Well sites can be onshore or offshore. In this exemplary system, a borehole 11 is formed in a subterranean formation by known means such as rotary drilling. Some embodiments may also use directional drilling, as described below.

A drill string 12 is suspended within the borehole 11 and has a bottom hole assembly 100 comprising a drill bit 105 at its lower end. The surface system includes a platform and a mast assembly 10 , which includes a rotary table 16 , a kelly 17 , a hook 18 and a swivel 19 , positioned on a well 11 . The drill string 12 is rotated by means of a disc 16 , which is powered by means not shown, and the drill string engages a kelly 17 at its upper end. The drill string 12 is suspended from a hook 18 attached to a moving block (also not shown) by a kelly 17 and a swivel joint 19, which allows the drill string to rotate relative to the hook. As is known, alternatively top drive systems can also be used.

In an example of this embodiment, the surface system further includes drilling fluid or mud 26 stored in a pit 27 formed at the wellsite. Pump 29 delivers drilling fluid 26 to the interior of drill string 12 via ports in swivel 19 such that the drilling fluid flows downward through drill string 12 as indicated by directional arrow 8 . Drilling fluid exits the drill string 12 through ports in the drill bit 105 and then circulates upwards through the annular region between the outside of the drill string and the drilling wall, as indicated by directional arrows 9 . In this known manner, the drilling fluid lubricates the drill bit 105 and, when it is recycled back into the pit 27, carries formation cuttings to the surface.

The bottom hole assembly 100 of the illustrated embodiment includes a logging while drilling (LWD) module 120 , a measurement while drilling (MWD) module 130 , a rotary steerable system and motor, and a drill bit 105 .

As is known in the art, LWD module 120 is housed within a special type of drill collar and may contain one or more known types of well logging tools. It should also be understood that more than one LWD module and/or MWD module may be used, as shown at 120A. (Throughout, reference is made to the module at position 120 or may also refer to the module at position 120A) The LWD module includes capabilities for measuring, processing and storing information, as well as for communicating with ground equipment. In this embodiment, the LWD module includes a resistivity measurement device.

As is known in the art, the MWD module 130 is also housed within a particular type of drill collar and may contain one or more devices for measuring drill string and drill bit characteristics. The MWD tool still further includes equipment (not shown) to generate electricity for the downhole system. This would typically include a mud turbine generator powered by the flow of drilling fluid, it being understood that other power sources and/or battery systems could also be used. In this embodiment, the MWD module includes one or more of the following types of measurement devices: weight-on-bit measurement device, torque measurement device, vibration measurement device, impact measurement device, stick/slip measurement device, orientation measurement device, and inclination measurement device .

An example of a tool is shown in FIG. 2, which may be the LWD tool 120, or may be part of the LWD tool kit 120A. As shown in FIG. 2, between the upper and lower transmitting antennas T1 and T2, there are upper and lower receiving antennas R1 and R2. Antennas are formed in recesses on the modified drill collar and mounted in insulating material. The phase shift of electromagnetic energy between receivers provides an indication of formation resistivity at relatively shallow depths of investigation, and the attenuation of electromagnetic energy between receivers provides an indication of formation resistivity at relatively deep depths of investigation. instruct. Reference can be made to US Patent No. US4899112 for further details. In operation, the attenuation-representing signal and the phase-representing signal are coupled to a processor, the output of which can be coupled to a telemetry circuit.

Recent electromagnetic (EM) logging tools use one or more oblique or transverse antennas, with or without axial antennas. These antennas can be transmitters or receivers. A tilted antenna is one whose dipole moment is neither parallel nor perpendicular to the longitudinal axis of the tool. A transverse antenna is one whose dipole moment is perpendicular to the longitudinal axis of the tool, and an axial antenna is one whose dipole moment is parallel to the longitudinal axis of the tool. A triaxial antenna is a type of antenna in which three antennas (ie, antenna coils) are arranged to be orthogonal to each other. Typically, one antenna (coil) is axial and the other two are transverse. Two antennas are considered to have equal angles if their dipole moment vectors intersect the longitudinal axis of the tool at the same angle. For example, two The two tilted antennas have the same tilt angle. The transverse antennas obviously have equal 90 degree angles, and this is true regardless of the azimuth relative to the tool.

Prior art logging tools/methods do not provide feedback or information to the operator to indicate the maximum depth of investigation of the tool when a boundary is not detected. Most depth and azimuth sensitive measurements have a depth of investigation that depends on the tool configuration and formation properties. Therefore, the depth of investigation (DOI), or volume of investigation (VOI) of azimuth-sensitive measurements should not be considered constant. We use the abbreviations "DOI" and "VOI" and their corresponding terms interchangeably herein.

The maximum DOI, azimuthal EM measurement for depths for which no stratigraphic boundaries are identified can be determined and displayed. This information can be used to optimize the use of this type of measurement, as well as optimize other types of depth read measurements. Applications include well location, formation property assessment, and reservoir structure assessment, to name a few. These applications can be implemented in real time or in recorded mode. For convenience and clarity, this disclosure discusses electromagnetic (EM) measurements here, although other types of measurements may also be used. Parameters can also be calculated using one or more sensor measurements, such as formation resistivity, distance to resistivity reference, fluid (water, oil, and gas) saturation, formation pressure, fracture pressure, and permeability sex.

Data collected at various depths along the drilling trajectory can be processed in real time, or it can be recorded and used for subsequent processing, or both. It is preferred to use a specific data format to allow data transfer across different 3D rendering platforms. The measurements themselves are usually measured over time, but other domains may also be used. For example, with LWD and MWD tools, downhole and surface sensors for pressure, temperature, fluid flow, etc. are used to obtain measurements. Because some parameters vary according to azimuth around the wellbore, certain logging sensors are designed to measure those parameters that vary according to azimuth. Those measurements enable detection and visualization of axial and azimuthal variations in the formation and wellbore. The characteristics and content of formation bedrock, formation fluid, drilling fluid, drilling cuttings and other constituent materials, size and shape of borehole, formation parameters and fluid parameters can be studied.

These data can be analyzed to determine the volume of clearing. For example, the volume of the cleaning may be a cylindrical volume centered on the axis of the tool. In one embodiment, the volume of the cylindrical clear is shaped like a "medicine box", with a radius proportional to the emitter-receiver distance, and a relatively short "height" compared to this radius. Volumes of other sizes and shapes are also possible. Measurements can be analyzed to study formation effects on measurements and to evaluate overall sensitivity (eg, maximum signal-to-noise ratio), since the signal still carries discernible formation property information. This analysis provides detection and visualization of axial, azimuthal and radial variations in formation geometry. Once determined, whether real or virtual, the volume of the 3D spatially oriented clearance located in the 3D environment can be displayed along the drilling trajectory. Color coding of one or more formation property boundaries may be produced in such a display. Multiple circles or ellipses of different sizes and shapes may be generated that are placed next to each other to represent a change (or lack of change) in volume of the clearing. Likewise, a 3D display of the distance between the tool and the maximum survey distance can be generated.

Using the obtained EM measurements, the vertical and horizontal resistivities of the anisotropic formations can be determined. Various frequencies and transmitter-receiver spacings (measurement couplings) are used to perform the measurements, resulting in various depths of investigation. From the determined resistivities, specific frequency and spacing combinations that provide the deepest DOIs can be identified. The identified measurement coupling that provides the deepest DOI can be used to determine the noise threshold. The noise threshold is the level of noise that makes the signal unreliable, difficult to determine and differentiate. The noise itself is usually frequency and transmitter-receiver spacing dependent and is characterized by the tool's electrical noise.

Returning to the determined resistivity, a resistivity ratio can be constructed to characterize a desired or assumed resistivity contrast. In one embodiment, the numerator of the ratio is the determined horizontal resistivity and the denominator is a user-defined or selected resistivity. The resistivity ratio and the identified measurement coupling can be used to model the signal response with respect to the tool's distance from the assumed or inferred formation boundary. As shown in Figure 3, the signal strength can be plotted against the depth of investigation distance. According to user needs, multiple positions and multiple sizes of noise thresholds can be set. For example, it can be set to two or three times the standard deviation of the noise. Other values may be selected based on other criteria. The noise threshold can be plotted as a horizontal line on the analog signal strength graph. The point at which the noise threshold line intersects the signal strength curve is referred to herein as the "cutoff point." The signal strength below the noise threshold is assumed to be too low to be reliable, so the maximum DOI corresponds to the cutoff point for which there is a reasonable confidence level in the signal. That is, in a given measurement environment, the point at which a vertical line descending from the cutoff intersects the horizontal axis is the maximum DOI of the tool.

FIG. 4 shows a flowchart 400 enumerating the steps described above. In step 402, data is obtained, and if the data is EM data, resistivity is determined (step 404). For other measurement types, other physical properties are similarly determined and used. As a function of the determined resistivity, the particular measurement coupling that yields the deepest DOI is identified (step 406). The identified measurement couplings are used to determine a noise threshold (step 408 ). A resistivity ratio is formed using the determined and selected resistivity values (step 410 ). Using the identified measurement coupling and resistivity ratio, the simulated signal response is determined as a function of DOI and plotted (step 412 ). The determined noise threshold is plotted on the signal response graph, and a cutoff point is determined (step 414). Then, a maximum DOI is determined based on the determined cutoff point (step 416).

One purpose of the DOI display is to graphically indicate to the user that even if no boundary is detected by inversion, based on the absent signal it can still be inferred that no boundary exists within the distance represented by the largest DOI. Therefore, the volume of the clearing can be determined. Based on the selected inversion input at any site, the user can estimate the maximum exploration depth. For example, evaluations can be based on resistivity distributions and inversion of other types of results. The resistivity distribution can be predetermined in prior work, or the user can enter, for example, if the resistivity of the conductive surrounding rock is known or estimated.

The detection range can be determined based on the inversion model. The DOI will produce an area that is clearly distinguishable from the true resistivity reference so as not to confuse physical boundaries. In one embodiment, three times the standard deviation of the noise of each measurement (eg, 0.025 dB attenuation for azimuth measurements, 0.15 degree phase shift in azimuth measurements) is used as a cutoff to estimate maximum DOI. DOI is not only dependent on the distance to the formation, but also on the resistivity reference value or distribution. The maximum DOI can be obtained by depth directional measurements taken from the input settings of the directional measurements. For example, if the input setup for directional surveys includes a 96 inch span measurement and a 34 inch span measurement, it is preferred to use the 96 inch span measurement to determine the maximum DOI. If the input setup for directional measurements includes 34 inch spacing measurements and 22 inch spacing measurements, it is preferred to use the 34 inch directional measurements to determine the maximum DOI.

For each site, formation model and tool location, the maximum DOI of the tool can be determined. When the stratigraphic model is a two-layer model, the maximum DOI can be determined by moving the boundary position until one of the depth-oriented measurements (perhaps 96 inches) falls below three times the standard deviation of the measurement. When the formation model is a three-layer model and the tool is in the middle layer, the maximum DOI of the lower boundary can be obtained by: fixing the upper boundary position, tool position, upper layer resistivity (Ru), middle layer horizontal resistivity (Rh) , the vertical resistivity (Rv) of the middle layer and the lower layer resistivity (Rl), and move the bottom boundary position until the absolute signal difference between the depth-oriented measurements with and without the lower boundary is less than the standard deviation of the measurements three times.

A synthetic three-layer example demonstrates the process. For example, the input formation model has Ru = 1 ohm-m, Rh = Rv = 30 ohm-m, and Rl = 2 ohm-m. As shown in Figure 5, the center layer thickness is 8 feet and the tool position is 2 feet below the upper boundary. The signal difference with and without the lower boundary plotted against the distance of the lower boundary to the tool position is plotted in FIGS. 6A-6D . According to Figure 6A (SAD1), the maximum DOI is 7.9 feet. In this case, tripling the measurement specification (0.25dB) yields two values: 7.9 feet and 17.6 feet. Choose a shorter value. According to Figure 6B (SAD4), the maximum DOI is 12.5 feet; according to Figure 6C (SPD1), 7.6 feet; and according to Figure 6D (SPD4), 12.8 feet. Currently commercial inversion methods can only provide one boundary solution, so the maximum DOI output by this process towards the lower boundary is in the range of 7.6 feet to 12.8 feet. This means that the directional measurements have sensitivity when the lower boundary is 12.8 feet away, however, the current inversion method only outputs a lower boundary when the boundary is 7.6 feet away from the tool.

The same logic can be used to determine the maximum DOI towards the upper boundary layer. When the stratigraphic model has more than 3 layers, the stratigraphic model is preferably first simplified to a three-layer model, and the above method is used to obtain the maximum DOI range. To simplify the formation model to a three-layer model, the following equation can be used to determine a weighted average based on the formation conductivity and the distance to the tool measured from the center of the formation.

${\stackrel{<span\; class="notranslate">\; \&OverBar;</span>}{\mathrm{<span\; class="notranslate">\; C</span>}}}_{\mathrm{<span\; class="notranslate">\; u</span>}}<span\; class="notranslate">\; =</span>\frac{{\mathrm{<span\; class="notranslate">\; \&Sigma;</span>}}_{\mathrm{<span\; class="notranslate">\; i</span>}<span\; class="notranslate">\; =</span>\mathrm{<span\; class="notranslate">\; 1</span>}}^{\mathrm{<span\; class="notranslate">\; N</span>}}{\mathrm{<span\; class="notranslate">\; e</span>}}^{{<span\; class="notranslate">\; -</span>\mathrm{<span\; class="notranslate">\; d</span>}}_{\mathrm{<span\; class="notranslate">\; iu</span>}}}<span\; class="notranslate">\; \&times;</span>{\mathrm{<span\; class="notranslate">\; C</span>}}_{\mathrm{<span\; class="notranslate">\; iu</span>}}}{{\mathrm{<span\; class="notranslate">\; \&Sigma;</span>}}_{\mathrm{<span\; class="notranslate">\; i</span>}<span\; class="notranslate">\; =</span>\mathrm{<span\; class="notranslate">\; 1</span>}}^{\mathrm{<span\; class="notranslate">\; N</span>}}{\mathrm{<span\; class="notranslate">\; e</span>}}^{{<span\; class="notranslate">\; -</span>\mathrm{<span\; class="notranslate">\; d</span>}}_{\mathrm{<span\; class="notranslate">\; iu</span>}}}}<span\; class="notranslate">\; ,</span>{\stackrel{<span\; class="notranslate">\; \&OverBar;</span>}{\mathrm{<span\; class="notranslate">\; C</span>}}}_{\mathrm{<span\; class="notranslate">\; l</span>}}<span\; class="notranslate">\; =</span>\frac{{\mathrm{<span\; class="notranslate">\; \&Sigma;</span>}}_{\mathrm{<span\; class="notranslate">\; i</span>}<span\; class="notranslate">\; =</span>\mathrm{<span\; class="notranslate">\; 1</span>}}^{\mathrm{<span\; class="notranslate">\; N</span>}}{\mathrm{<span\; class="notranslate">\; e</span>}}^{{<span\; class="notranslate">\; -</span>\mathrm{<span\; class="notranslate">\; d</span>}}_{\mathrm{<span\; class="notranslate">\; il</span>}}}<span\; class="notranslate">\; \&times;</span>{\mathrm{<span\; class="notranslate">\; C</span>}}_{\mathrm{<span\; class="notranslate">\; il</span>}}}{{\mathrm{<span\; class="notranslate">\; \&Sigma;</span>}}_{\mathrm{<span\; class="notranslate">\; i</span>}<span\; class="notranslate">\; =</span>\mathrm{<span\; class="notranslate">\; 1</span>}}^{\mathrm{<span\; class="notranslate">\; N</span>}}{\mathrm{<span\; class="notranslate">\; e</span>}}^{{<span\; class="notranslate">\; -</span>\mathrm{<span\; class="notranslate">\; d</span>}}_{\mathrm{<span\; class="notranslate">\; il</span>}}}}$

In the equation, d _iu is the distance from the boundary of the upper layer to the center of the i-th layer from the top, C _iu is the conductivity of the i-th layer from the top, and d _il is the distance from the boundary of the lower layer to the center of the i-th layer from the bottom The distance from the center of layer i, C _il is the conductivity of the i-th layer from the bottom.

The DOIs defined in this case share some similarities in the signal-to-noise ratio mentioned above. Both indicate whether the measurement signal is a good indicator of the presence of a boundary. However, quantization is different. The signal-to-noise ratio provides an easy way to indicate whether the signal measured for a particular tool location is below the noise specification. However, any other explanation for the existence of the distant frontier is worthless. On the other hand, the DOI states how far the boundary needs to be before the measurement becomes insensitive, thus giving a confidence to explain when the inversion boundary is within the calculated detection range.

It should be understood that while the invention has been described with reference to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will recognize that other embodiments may be made without departing from the scope of the invention disclosed herein. design. Accordingly, the scope of the invention should be limited only by the appended claims.

Claims (18)

CLAIMS 1. A method for determining the volume of a cleanup surrounding a wellbore comprising: Provide logging tools; using the logging tool to obtain properties of the subterranean formation; determining a noise threshold based on a selected transmitter-receiver measurement coupling of the logging tool and electrical noise of the logging tool; determining a resistivity ratio based on the received measurements; using the resistivity ratio to simulate a signal response of the logging tool; plotting a first curve as a function of signal strength and depth of investigation distance and representing the signal response, and a second curve representing the noise threshold; determining a depth of investigation distance corresponding to a point on the graph where the first curve and the second curve intersect as a maximum depth of investigation into the subterranean formation; and Use the determined maximum depth of investigation to determine the volume of clearing. 2. The method of claim 1, wherein the providing comprises deploying the logging tool on a wireline, drill string, or wireline drill pipe. 3. The method of claim 1, wherein said obtaining formation characteristics comprises transmitting and receiving an electromagnetic signal transmitted at a particular frequency, or transmitting and receiving a plurality of electromagnetic signals, each of said electromagnetic signals at a different frequency to transmit. 4. The method of claim 1, wherein the formation properties include at least one of the following: voltage, bulk resistivity, horizontal resistivity, vertical resistivity, porosity, permeability, fluid saturation, NMR relaxation time, magnetic field, acoustic response, well size, well shape, drilling fluid composition, MWD parameters and LWD parameters. 5. The method of claim 1, wherein no boundary layer is detected. 6. The method of claim 1, further comprising using the determined volume of clearance for at least one of well location, formation property assessment, and reservoir structure assessment. 7. The method of claim 1, further comprising displaying the volume of the clearing. 8. The method of claim 7, wherein the displaying includes color coding one or more formation property boundaries. 9. The method of claim 7, wherein the displaying includes adjacently placing a plurality of circles or ellipses of different sizes. 10. The method of claim 7, wherein the displaying comprises mapping a volume of a 3D spatially oriented clearing located in a 3D environment along the drilling trajectory. 11. A system for determining the volume of clearance around a wellbore comprising: logging tools; and a processor configured to: obtaining properties of the subterranean formation using the logging tool; determining a noise threshold based on a selected transmitter-receiver measurement coupling of the logging tool and electrical noise of the logging tool; determining a resistivity ratio based on the received measurements; using the resistivity ratio to simulate a signal response of the logging tool; plotting a first curve as a function of signal strength and depth of investigation distance and representing the signal response, and a second curve representing the noise threshold; determining a depth of investigation distance corresponding to a point on the graph where the first curve and the second curve intersect as a maximum depth of investigation into the subterranean formation; and The determined maximum depth of investigation is used to determine the volume of the clearing. 12. The system of claim 11, wherein the logging tool is deployed on a wireline, drill string, or wireline drill pipe. 13. The system of claim 11, wherein no boundary layer is detected. 14. The system of claim 11, wherein the formation properties include at least one of the following: voltage, bulk resistivity, horizontal resistivity, vertical resistivity, porosity, permeability, fluid saturation, NMR relaxation time, magnetic field, acoustic response, well size, well shape, drilling fluid composition, MWD parameters and LWD parameters. 15. The system of claim 11, further comprising using the determined volume of clearance for at least one of well location, formation property assessment, and reservoir structure assessment. 16. The system of claim 11, further comprising displaying a volume of the clearing. 17. An apparatus for determining the volume of clearance surrounding a wellbore comprising: modules for providing logging tools; a module for obtaining a characteristic of a subsurface formation using the logging tool; means for determining a noise threshold based on a selected transmitter-receiver measurement coupling of the logging tool and electrical noise of the logging tool; means for determining a resistivity ratio based on the received measurements; means for simulating a signal response of the logging tool using the resistivity ratio; means for plotting a first curve as a function of signal strength and depth of investigation distance and representing the signal response, and a second curve representing the noise threshold; means for determining a depth of investigation distance corresponding to a point on the graph where the first curve and the second curve intersect as a maximum depth of investigation into the subterranean formation; and Module for determining the volume of a clearing using the determined maximum depth of investigation. 18. The apparatus of claim 17, wherein the logging tool is a logging while drilling tool.